In most petroleum wells heretofore, and increasingly as petroleum reserves are depleted, petroleum must be withdrawn from an oil producing formation zone of a well by mechanical lifting equipment driven by a motive source at the surface, which is either of the reciprocating or rotary type. In a typical installation, the motive source at the surface comprises, in the case of a reciprocating pump, an electrically driven pump jack, and in the case of a rotary type pump, an electrically driven rotary drive.
In a typical configuration of an oil well, a hole or wellbore is drilled from the surface to a depth somewhat below a geological formation that bears petroleum. Inside this wellbore and extending the full depth of the wellbore a string of pipe is installed that is referred to as casing, consisting of segments of threaded pipe serially connected by couplers. The annulus between the casing and the surrounding earthen wall of the drilled wellbore is filled with cement, and as such, the casing is installed on a permanent basis. At the surface the casing is connected to a wellhead, an apparatus of various connections, valves, and seals, as well as the pump driving system whereby the several operations of the well are isolated and managed by the operator.
At that depth where the casing passes through the oil bearing geological formation, the casing and the cement enclosing it are perforated to allow fluid to flow from the formation into the casing. Within the casing is installed a second smaller diameter string of pipe referred to as tubing. Like the casing, the smaller diameter tubing consists of segments of end threaded pipe connected one to another and extends from the wellhead to the depth at which the pump is installed, near the bottom of the wellbore and casing, and usually below the perforations. At the end of the tubing the pump is installed, an elongated multi-component apparatus which is approximately 30 feet in length, and has a fluid intake element located at its bottom. The pump, be it of the reciprocating type or the rotational type, is powered from the surface by either a pump jack or a rotary drive, with power being transferred down the wellbore to the pump by a sucker rod string. A sucker rod string consists of lengths of solid steel rods threaded on each end and connected one to another with threaded couplings. In the case of a reciprocating type pump, the sucker rod string is attached at the surface to the pump jack, from which point it runs down the inside of the tubing to the plunger element of the reciprocating pump. The pump jack at the surface cyclically lifts and lowers the sucker rod string which in turn lifts and lowers the plunger of the pump below.
In the case of rotary type pumps, the rotary drive at the surface rotates the sucker rod string which is attached to and rotates the rotor element of the rotary pump at the bottom of the well. As either the plunger element of the reciprocating pump cycles up and down or the rotor element of the rotational pump rotates, fluid is pumped up the annulus between the sucker rod string and the tubing to the surface.
Fluid from the oil bearing formation flows through the perforations in the casing and into the annulus between the casing and the smaller tubing. As the pump operates, fluid is drawn into the pump from the annulus between the tubing and the sucker rod string and pumped up the tubing to the wellhead. At the wellhead the fluid branches off to a flowline and is delivered to a storage tank or other facility.
In any well that utilizes any form of pumping apparatus to lift the formation fluid to the surface, long term production is optimized if the rate at which the pump evacuates the fluid to the surface is equal to the rate at which the fluid flows from the formation through the perforations into the well. Due, however, to constantly changing and unpredictable formation flow rates in combination with the shortcomings of existing monitoring equipment, this balance is rarely attained.
To best cope with this situation a procedure involving on-off sequencing of the pumping operation is most frequently employed. In this procedure the pump is allowed to pump at a pace exceeding the formation flow rate until it has emptied the well of fluid. At that point, in the case of reciprocating plunger pumps, the plunger draws a large amount of air rather than fluid into the pump barrel on its upstroke, and then, without the normal cushioning resistance of fluid, pounds forcefully into the air/fluid interface in the barrel on the downstroke. This pounding greatly stresses and ultimately will damage numerous elements of the pump apparatus including the sucker rod string, the barrel and plunger of the pump, the gearbox, motor, and structural components of the pump jack, and to a lesser extent the tubing string.
This condition is referred to in the industry as being “Pumped Off” and pumps are typically equipped with a sensor that detects the shock waves resultant from the Pumped Off condition when it occurs. That particular sensor and the related equipment is known as a Pump Off Controller or POC, which is programmed to automatically shut down the pump jack when it identifies the Pumped Off condition.
The POC is further programmed to, after a pre-set period of time, turn the pump jack back on whereby pumping can resume. The pre-set period of time is set by the operator and is intended to be long enough to allow the formation flow to refill the well to a level that provides a practical reservoir of pump-available fluid.
Dependent on the particular well characteristics, this on/off cyclic pumping method may be programmed to cycle as frequently as six times per hour. Several disadvantages are inherent in this procedure.
Due to the inertia of the pump jack equipment and the counterweight, the pump is likely to pound several strokes prior to stopping completely after the POC has switched it off. This pounding results in shorter equipment life, longer downtime, and more maintenance requirements in all respects. Also for a brief time upon startup an electric motor uses from three to six times the electrical power required for normal continual running. Hence, the energy consumption in a start-stop operation greatly exceeds that used in constant operating conditions.
The most fundamental factor as to the quantity of production from a well is the rate at which fluid from the oil bearing zone of the geological formation initially flows through the perforations into the well to become available to be pumped to the surface. The rate of this flow of fluid into the casing/tubing annulus is a consequence of the degree of natural formation pressure available at the depth of the casing perforations. If the casing/tubing annulus into which the fluid flows is empty at the level of the perforations, the flow rate will take full advantage of the natural formation pressure and such flow will then be at the maximum rate possible, at least for a time. If, however, the casing is not empty at the perforation depth and has filled to some height above the perforations, the natural formation pressure and the consequent flow rate will be opposed by the backpressure or head pressure created by the height of the fluid already in the casing/tubing annulus. Hence, the rate of flow is directly influenced by the amount of backpressure exerted on the formation by the head of the column of produced fluids in the casing at any given time. The more head pressure against the formation flow, the slower that flow will be. Consequently, the most productive flow from the formation into the well occurs if the column level is constantly held at the very minimum height required for continuous pumping. The typical on/off cyclic pumping method described above fails in this respect. During a large percentage of the shut down times, when the well is refilling itself, and during the initial period of pumping after the timer has restarted the pump jack, the fluid level in the well is higher than necessary, and the formation flow is thereby unnecessarily retarded by the excessive back pressure.
The flow of fluid through the geological formation surrounding the well is also disadvantaged by the on/off cyclic pumping method. While the flow of fluid in the formation is a complex and multifaceted subject, it is generally accepted that maintaining constant movement without stoppages will enhance the flow rate of producible fluid delivered to the well.
Workers in the art have long been aware of the benefits of matching pumping extraction rates to formation fluid inflow rates. Techniques have been devised for detecting a variety of information concerning changes in flow rates and other operating conditions of the well in addition to the shock waves produced by the Pumped Off condition. Using such instrumentation, pumps have been run with variable speed drives or with on/off duty cycle timing in an effort to match formation inflow to pump output flow rates. Such systems have not, however, been directly responsive to production conditions or flow rate variations, and consequently have not been as efficient as theorized.
An advanced system of this nature is sold as a “well manager” under the “SAM” trademark, being manufactured by Lufkin Automation in Lufkin, Tex. This system carries out a number of functions in order to improve the pumping operation of sucker rod based marginally producing wells. It comprises a pump controller which monitors the operation of various mechanical components in addition to the condition and performance of the sucker rod string and downhole plunger pump. The “SAM” system senses the Pumped Off event by a strain gage and signals the motor to shut off. This again cannot be done immediately due to inertia in the system, so that a number of undesired shock impacts will follow each shut off command. The system then shuts down for a pre-selected length of time, varying with the conditions, to allow replenishment from the production zone.
This so-called “well manager” unit utilizes downhole detectors positioned near the down hole production zone level and line connected along the tubular system to the control system at the wellhead. These detectors provide real time and direct electrical inputs to the system as to the fluid levels in the pumping zone. To do this, the system must utilize expensive, sensitive and delicate pressure sensing gages and connect them by electric wire strung the entire length of the tubing string up the well to the wellhead. The system is difficult to install and maintain in satisfactory operating condition because of the non-robust components and the long electrical connection through the wellbore that is needed. It is adequate for real time monitoring of conditions in the production zone, but is subject to shock waves generated by the Pumped Off conditions. It is also very expensive and consequently is not widely utilized in well production installations.
There is therefore a need for a mechanical system which can monitor actual fluid level variations in the pumping zone and transmit operating data reliably from downhole locations to surface pump controls for maximizing production under varying operating conditions.